In conventional pyrolysis processes using pyrolysis furnaces, reaction mixtures of feed hydrocarbons and steam flow through long coils or tubes which are heated by combustion gases to produce ethylene and other olefins, as well as other valuable by-products. The combustion gases are produced from natural or pyrolysis gases or fuel oils and air. The hot combustion gases are passed around the coils, counter-current to the hydrocarbon feedstock flow through the coil. Heat is transferred from the hot combustion gases to the walls of the tubes and then coil walls to the hydrocarbon feedstock passing within the coils. The hydrocarbon feedstock is heated within the coils from about 100.degree. C. to higher temperatures, typically in the range of about 750.degree. to 950.degree. C. in the last few years, there has been a trend to heat the hydrocarbon feedstock to the higher temperatures in order to obtain increased amounts of ethylene production per given amount of feed.
Unfortunately coke is always produced as a reaction by-product and collects on the coil inner walls, and the high operating temperatures tend to promote or increase this phenomenon. Coke formation has several deleterious effects including the following:
(a) Coke formation on the inner walls of the coil results in increased resistance to heat transfer to the hydrocarbon feed. Thus, a smaller fraction of the heat of combustion is transferred to the hydrocarbon feed and a larger fraction of the combustion gas heat is lost to the surroundings in the stack gas. PA1 (b) Due to the increased resistance to heat transfer, the temperature of the wall of the coil must be heated to even higher temperatures to adequately heat the hydrocarbon feed within the coil. This results in increased corrosion of the coil walls and a shorter life for the expensive high-alloy coils. PA1 (c) The coke build-up in the coil results in larger pressure drop for the hydrocarbon feed flowing through the coils, since the flow path is more restricted. As a consequence, more energy is required to compress the hydrocarbon product stream in the downstream portion of process. PA1 (d) The coke build-up in the coil restricts the volume in the reaction zone, thereby decreasing the yield of ethylene and other valuable by-products. Hence, more hydrocarbon feedstock is needed to produce the required amounts of product. PA1 (a) Increased levels of production of lower olefins, including both ethylene and propylene. PA1 (b) Time of operation between de-coking is substantially lengthened and maintenance problems reduced. PA1 (c) Coke build-up in both the pyrolysis coils and TLX's is reduced. In many cases, essentially no coke accumulates in the coil, resulting in more uniform and more stable operation during the entire pyrolysis cycle. Otherwise, as coke is deposited, small but significant changes in operation are normally required. PA1 (d) Economically speaking, energy requirements are reduced, including lower fuel requirements for pyrolysis furnaces, greater steam production from TLX's, and lower energy requirements for compressors. PA1 (e) The expensive high-alloy steel coils in the pyrolysis furnace and the TLX's are replaced less frequently. PA1 (f) Flexibility to use different hydrocarbons as feedstock is increased.
Coke formation is also a problem in transfer line exchangers (often referred to as TLX's, TLE's, or quench coolers). The objective of a TLX is to recover as much of the sensible heat as possible from the hot product stream leaving the pyrolysis furnace. This product stream contains steam, unreacted hydrocarbons, and the desired products and by-product. High-pressure steam is produced as a valuable by-product in the TLX, and the product mixture is cooled appreciably. As in the coil of the pyrolysis furnace, coke formation and/or collection in the TLX results in poorer heat transfer, which in turn results in decreased production of high-pressure steam. Coke formation in the TLX also results in a larger pressure drop for the product stream.
In current pyrolysis furnaces, coke formation in the pyrolysis coils and/or in the TLX eventually becomes so great that the coils and/or the TLX must be cleaned.
Although various cleaning techniques have been suggested or tried, the pyrolysis unit is usually shut down (i.e., the feedstream flows are suspended). The flow of steam, however, is generally continued since steam reacts slowly with the deposited coke to form gaseous carbon oxides and hydrogen.
Moreover, air is often added to the steam. At the high temperatures in the coil, the coke in the coil reacts quite rapidly with the oxygen in the air to form carbon oxides. After several hours, the coke in the coil is almost completely removed. This cleaning step is frequently referred to as "De-coking." The coke in the TLX is not as easily removed or gasified, however, due to the lower temperatures in the TLX as compared to the coil.
Cleaning or de-coking of the TLX is, thus, often accomplished by mechanical means. Certain mechanical de-coking means have also been used or can be used for cleaning the coil.
De-cokings frequently require at least one day and sometimes two days in conventional units, de-cokings are made approximately every 30 to 60 days. De-coking obviously results in increased downtime relative to ethylene production time, frequently amounting to a several percent loss of ethylene production during the course of a year. De-coking is also relatively expensive and requires appreciable labor and energy.
In 1992, almost 42 billion pounds of ethylene were produced in the U.S., primarily by the above-described process. It is anticipated that this will increase to about 49 billion tons by 1998. In the Pacific rim countries, about 7 billion pounds of ethylene were produced in 1992, primarily by the above-described process. It is anticipated that production will increase to 40 billion tons by the year 2000. A method to extend the time between de-cokings is highly desirable.
Numerous suggestions have been made as to how to eliminate or minimize coke formation in ethylene pyrolysis units. For example, improved control of the operating conditions or improved feedstock quality has resulted in small decreases in the rate of coke formation. The cost of making such changes, however, is often high so that these changes are frequently not cost effective.
Several processes have been reported in which various additives claimed to be either inhibitors or catalysts are added to the hydrocarbon-steam feed stream. If the additive is an inhibitor, coke (or carbon) formation is inhibited, or minimized. If the additive is a catalyst, reactions between the coke and steam are presumably promoted, or catalyzed. In such a case, the formation of carbon oxides (CO or CO.sub.2) and hydrogen are promoted. In either case, the net rate of coke that collects on the metal surfaces is decreased.
Sulfur, an additive, has been proposed to reduce coke formation in Great Britain Patent No. 1,090,933, German Patent No. 1,234,205 and French patent No. 1,497,055. At the least, part of the beneficial effect of sulfur is generally considered to be caused by conversion of metal oxides on the inner surfaces of the coil walls to metal sulfides. The metal sulfides tend to destroy the catalytic effect of metal oxides which promote coke formation. Although sulfur may act as an inhibitor, it also frequently promotes the destruction of the coil metal walls because the metal's corrosion resistant, protective oxide layer has been replaced by metal sulfides which tend to flake off or be lost from the surface. Moreover, at high temperatures, some sulfides, such as nickel sulfide, liquify.
Other additives reported include phosphorous pentoxide (see L. M. Aserizzi, J. Hydrocarbon Processing, 1967, Vol. 46, pg. 4) and ammonium nitrate (see U.S.S.R. Patent No. 191,726). These latter compounds obviously break down at the high temperatures and oxides of nitrogen are likely to form.
Potassium carbonate has also been proposed as a feedstream additive in U.S. Pat. No. 2,893,941 to Kohfeldt and Herbert. In using such an additive, provisions must be made to introduce a relatively small but equal amount of the salt to each of several coils in a pyrolysis furnace. One method is to add an aqueous solution of the salt in measured amounts into the feedstream of each pyrolysis unit. As the potassium carbonate is heated in the coil to the pyrolysis temperatures, part or all of its apparently decomposes, perhaps forming K.sub.2 O, and part deposits on the coke present on the walls. Such deposits apparently catalyze the gasification between coke and steam so that at typical pyrolysis conditions the net formation of coke on the surfaces of the coils is low if not essentially zero. Corrosion on the inner surface of the coil has been found to be a problem in the process described in U.S. Pat. No. 2,893,941. Although details on what causes corrosion in this process are not known, solid deposits resulting from the potassium carbonate are known to sometimes occur, especially if the quantity of the carbonate added is not controlled correctly. Such deposits may cause intercrystalline cracking on the metal surface. Tests have been made in commercial units to find operating conditions in which corrosion is not a problem. Adding various levels of potassium carbonate and different concentrations of solutions were, for example, investigated, but no suitable set of operating conditions was found. No conditions were found which resulted in both coke-free surfaces and minimal corrosion.
U.S. Pat. No. 4,889,614 to Forester has reported a method for reducing coke formation using magnesium acetate, magnesium nitrate, calcium acetate, calcium nitrate, or calcium chloride as an additive. He investigated all six salts and found that the rate of coke formation on stainless steel surfaces was reduced in the temperature range of 1400.degree. to 2050.degree. F. Such a temperature range is used in all, or at least most, commercial pyrolysis units. He reported the percent reduction in the rates of coke formation or deposition based on numerous runs made with and without the use of one of the salts. He found, however, that corrosion of stainless steel was a major problem. Small, but significant, amounts of Fe.sub.3 O.sub.4, NiO.sub.2, Cr.sub.2 O.sub.3, and MnO.sub.2 were present in the coke. The laboratory coil had to be replaced after 20-30 laboratory runs, which were normally 160 minute runs.
The process described in U.S. Pat. No. 4,889,614 is apparently considerably less effective in removing or minimizing coke deposition as compared to the process of U.S. Pat. No. 2,893,941. For example, calcium acetate resulted in a coke reduction of only 24% (see Table II of the '614 patent), although somewhat higher reductions occurred with magnesium nitrate and magnesium sulfate. Moreover, based on the results reported, corrosion would be so severe that the process would likely be of no commercial interest. There is also no indication that the process would be effective in minimizing coke formation in the TLX, which operates at much lower temperatures than the coils.
In conclusion, no satisfactory method has to date been reported using additives for controlling coking problems. Those processes that did control the coking problems resulted in major disadvantages that rendered the process economically unfeasible.